So-called “impregnated” drag bits are conventionally used for drilling hard and/or abrasive rock formations, such as sandstones. Such impregnated drill bits conventionally employ a cutting face composed of superabrasive cutting particles, such as natural or synthetic diamond grit, dispersed within a matrix of wear-resistant material. During drilling, the matrix and the embedded diamond particles experience wear. Worn cutting particles become lost from the cutting face and new cutting particles are exposed. The abrasive particles may include natural or synthetic diamonds and may be integrally cast with the body of the bit, as in low-pressure infiltration. Additionally, features of a drill bit having abrasive particles may be preformed separately from the bit body, as in hot isostatic pressure infiltration, and subsequently attached to the bit by brazing or by furnacing them to the bit body in an infiltration process during manufacturing of the bit.
It is recognized that conventional impregnated bits generally exhibit a poor hydraulics design, often employing a “crow's foot” to distribute drilling fluid across the bit face and, thus, providing only minimal flow area for the drilling fluid. Further, conventional impregnated bits do not drill very effectively when the bit encounters softer and less abrasive layers of rock, such as shales. When drilling through shale, or other soft formations, with a conventional impregnated drag bit, the cutting structure tends to quickly clog or “ball up” with formation material, reducing the effectiveness of the drill bit. The softer formations can also result in the plugging of fluid courses formed in the drill bit, causing heat buildup and premature wear of the bit. Therefore, when shale-type formations are encountered, a more aggressive bit is desired to achieve a higher rate of penetration (ROP). It follows, therefore, that selection of a bit for use in a particular drilling operation becomes more complicated when it is expected that formations of more than one type will be encountered during the drilling operation.
One type of impregnated bit used to drill in varied formations includes that which is described in U.S. Pat. No. 6,510,906, issued to Richert et al. (hereinafter “the Richert '906 patent”) and assigned to the assignee hereof, the disclosure of which is incorporated by reference herein in its entirety. The Richert '906 patent describes a drill bit employing a plurality of discrete, post-like, abrasive, particulate-impregnated cuffing structures extending upwardly from abrasive particulate-impregnated blades. The blades define a plurality of fluid passages along the bit face. In one embodiment, polycrystalline diamond compact (PDC) cutters are placed in a relatively shallow cone portion of the bit. The PDC cutters may be used to promote enhanced drilling efficiency through softer, non-abrasive formations. A plurality of ports, configured to receive nozzles therein, are distributed on the bit's face to improve drilling fluid flow and distribution. The Richert '906 patent describes various configuration of the blades including blades that extend radially in a linear fashion as well as blades that are curved or spiral outwardly to a gage portion.
Another impregnated drag bit is described in U.S. Pat. No. 6,843,333 issued to Richert et al. (hereinafter “the Richert '333 patent”) and assigned to the assignee hereof, the disclosure of which is incorporated by reference herein in its entirety. The Richert '333 patent describes another drill bit that employs a plurality of discrete, post-like, abrasive, particulate-impregnated cutting structures extending upwardly from abrasive, particulate-impregnated blades. In one embodiment described in the Richert '333 patent, discrete protrusions extend outwardly from at least some of the plurality of discrete cutting structures. The discrete protrusions are formed of a material such as a thermally stable diamond product. In one particular embodiment, the discrete protrusions exhibit a generally triangular cross-sectional geometry relative to the direction of intended bit rotation. It is stated that such discrete protrusions act as “drill out” features that enable the bit to drill through certain structures such as a float shoe or hardened cement at the bottom of a well bore casing.
However, there is an ongoing desire to improve the effectiveness of drill bits, including so-called impregnated drag bits. For example, it would be beneficial to design a durable drill bit that provides more aggressive performance in softer, less abrasive, formations while also providing effective ROP in harder, more abrasive, formations without requiring increased weight on bit (WOB) during the drilling process.